System and Method for Autonomous Tools

ABSTRACT

Autonomous tools for use in tubular members associated with managing hydrocarbons. The autonomous tools are at least partially fabricated from a dissolvable material, which is configured to dissolve in the fluid within the tubular member. The autonomous tool includes one or more components that determine the location of the autonomous tool within the tubular member and actuate the actuatable tool component once a predetermined or selected location has been reached within the tubular member.

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application Ser.No. 62/329,690 filed Apr. 29, 2016, the entirety of which isincorporated by reference herein.

FIELD OF THE INVENTION

The present techniques relate to the field of autonomous tools. Inparticular, the present techniques involve autonomously performingtubular operations, such as perforating and/or treating subterraneanformations to enhance production of hydrocarbons from subsurfaceformations. More specifically, the present techniques provide a methodand system for perforating, isolating, and/or treating an interval ormultiple intervals without need of a wireline or other running stringand performing such tubular operations with an autonomous tool that hasat least a portion of the autonomous tool fabricated from a dissolvablematerial.

BACKGROUND

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present disclosure.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presentdisclosure. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

In the drilling of oil and gas wells, a wellbore is formed using a drillbit that is attached to the end of a drill string. The drill bit anddrill string are used to form a wellbore within a subsurface region byremoving rock and other materials. After drilling to a predetermineddepth, the drill string and drill bit are removed from the wellbore. Theresulting wellbore forms an open space within the subsurface formation.

Once the wellbore is formed, one or more sets of casing string areinstalled in the wellbore. The casing strings are lowered into thewellbore and are secured together to form the one or more sets of casingstrings. An annular area is thus formed between the one or more sets ofcasing strings and the surrounding formations. Then, cementingoperations may be conducted to fill the annular area with cement, whichforms a cement sheath. The combination of cement and casing strengthensthe wellbore and facilitates the isolation of the formations fluidsbehind the one or more sets of casing strings.

If several casing strings are utilized, the casing strings typicallyhave progressively smaller diameters. Thus, the process of drilling,installing casing strings and cementing the different diameters ofcasing strings is repeated several or even multiple times until thedepth of the well has reached a predetermined level. The final string ofcasing, which is referred to as a production casing, is cemented intoplace near the surface of the formation. In some instances, theproduction casing may have a liner, which is a casing string that is nottied back to the surface, but is secured from the lower end of thepreceding casing string.

To provide access to hydrocarbons in the subsurface formation, one ormore tubular operations (e.g., completion operations or processes) maybe performed within the wellbore. For example, the production casing andthe associated cement may be perforated at desired levels. Theperforations are lateral holes that are shot through the casing stringsand the cement sheath surrounding the casing strings to provide a pathfor hydrocarbons to flow into the wellbore. Following the perforations,the subsurface formation is fractured to provide flow paths through thesubsurface formation. The hydraulic fracturing may include injectingfracturing fluid (e.g., viscous fluids that are usually shear thinning,non-Newtonian gels or emulsions) into the subsurface formation at highpressures and rates that the reservoir rock of the subsurface formationfails and forms a network of fractures. The fracturing fluid istypically mixed with a granular proppant material, such as sand, ceramicbeads, or other granular materials. The proppant serves to hold thefracture(s) open after the hydraulic pressures are released. Thecombination of fractures and injected proppant increases the flowcapacity of the treated portion of the subsurface region.

As another tubular operation, one or more acidizing operations may beperformed to further stimulate the subsurface formation and to clean thenear-wellbore regions downhole within the subsurface formation. Theacidizing operations may include injecting an acid solution down thewellbore and through the perforations. The use of an acidizing fluid isparticularly beneficial when the subsurface formation includes carbonaterock. In such tubular operations, the acidizing operations may involveinjecting a concentrated formic acid or other acidic composition intothe wellbore, and directing the acid solution into selected zones ofinterest. The acid solution dissolves the carbonate material, therebyopening porous channels through the hydrocarbons to provide flow pathsinto the wellbore. In addition, the acid solution may further dissolvedrilling mud that may have invaded the subsurface formation.

Further, another tubular operation may include the isolation of variouszones for pre-production treatment to treat the intervals in stages.This involves the use of diversion methods. In petroleum industryterminology, “diversion” means that injected fluid is diverted fromentering one set of perforations so that the fluid primarily enters onlyone selected zone of interest. Where multiple zones of interest are tobe perforated, the tubular operations may involve that multiple stagesof diversion be carried out. The diversion methods may includemechanical devices (e.g., bridge plugs, packers, down-hole valves,sliding sleeves, and baffle/plug combinations); ball sealers;particulates (e.g., sand, ceramic material, proppant, salt, waxes,resins, or other compounds); chemical systems (e.g., viscosified fluids,gelled fluids, foams, or other chemically formulated fluids); andlimited entry methods.

Examples of such techniques are provided in U.S. Pat. Nos. 6,394,184;6,543,538; 7,357,151; and 7,467,778; which are referred to andincorporated herein by reference in their respective entirety. Thedocuments describe various techniques for running a bottom hole assembly(“BHA”) into a wellbore, and then creating fluid communication betweenthe wellbore and various zones of interest. The BHA may includemechanically actuated, re-settable axial position locking devices, orslips; an inflatable packer or other sealing mechanism; perforatingguns; a casing collar locator; and a translating assembly, such as astring of coiled tubing, conventional jointed tubing, a wireline, anelectric line, or a downhole tractor. The perforating guns may furtherhave associated charges. The translating assembly may provide amechanism for moving the BHA within the wellbore from the surface andmay provide electrical signals to the perforating guns. The electricalsignals cause the charges to detonate, thereby forming perforations atthe location that the perforating guns are positioned. This location isbased on the judgment from the operator of the wireline equipment.

To enhance operations, such techniques utilize friable tools to performvarious operations. For example, U.S. Patent Application PublicationNos. 20130062055; 20130062072; 20130255939; 20140131035, which arereferred to and incorporated herein by reference in their respectiveentirety, describe autonomous units and methods for downhole, multi-zoneperforation and fracture stimulation for hydrocarbon production. Theseautonomous units may be fabricated into tools and may be fabricated froma friable material, such as ceramic or some other frangible material.The autonomous tools are utilized to be dropped or pumped down hole.Upon completion of the desired activity, the tool breaks apart to createsmall chards of material, which are not intended to obstruct thewellbore. The chards may fall to bottom of the wellbore, may be pumpedinto the formation, or may flow out of the well during production.However, certain tools may not be fabricated from ceramic materialseconomically and/or may be difficult to reliably reduce to sufficientlysmall fragments via explosives. These tools may be made from materialsthat do not break-up appropriately and/or have the potential to plug aperforation channels. With the use of two or more autonomous tools in asingle well, the potential exists to hinder operations with theaccumulation of debris, which is problematic.

Accordingly, there remains a need in the industry for apparatus,methods, and systems that provide enhancements to performing tubularoperations. The present techniques overcomes the drawbacks ofconventional approaches by using autonomous tools that include at leasta portion of the components being formed from a dissolvable material. Inparticular, the present techniques may include, but are not limited to,autonomous tools having special connections between friable tools and/orinternal components, such as electronic boards, retention devices,packing or filler for shock absorption, and the like, being at leastpartially fabricated from dissolvable materials.

SUMMARY

In one or more embodiments, an assembly and method describes anautonomous tool for use in tubular operations. The autonomous toolincludes an actuatable tool component configured to perform a tubularoperation; a location component configured to determine a location ofthe autonomous tool within a tubular member; and an on-board controllerconfigured to send an actuation signal to the actuatable tool componentwhen a predetermined location has been reached within the tubularmember. The actuatable tool component, the location component, and theon-board controller are arranged to be deployed together in the tubularmember as a single autonomous tool; the actuatable tool component isconfigured to autonomously perform the tubular operation in response tothe actuation signal; and at least a portion of the actuatable toolcomponent, the location component, and the on-board controller arefabricated from a dissolvable material configured to dissolve whensubjected to tubular conditions.

Further, in one or more other embodiments, a method for performing atubular operation is described. The method includes: deploying anautonomous tool into a tubular member, wherein at least a portion of theautonomous tool is fabricated from dissolvable material and theautonomous tool is configured to autonomously perform the tubularoperation; autonomously performing the tubular operation with theautonomous tool; dissolving the at least a portion of the autonomoustool that is fabricated from dissolvable material; and managinghydrocarbons from the tubular member.

Moreover, in certain embodiments, the autonomous tool may include two ormore actuatable tool components. Each of the two or more actuatable toolcomponents may be configured to perform a specific tubular operation,which may be performed in a specific sequence. The on-board controllermay communicate instructions to the two or more actuatable toolcomponents to manage sequence of tubular operations.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present techniques can be better understood, certaindrawings, charts, graphs and/or flow charts are appended hereto. It isto be noted, however, that the drawings illustrate only selectedembodiments of the inventions and are therefore not to be consideredlimiting of scope, for the present techniques may admit to other equallyeffective embodiments and applications.

FIG. 1 is an exemplary flow chart of a method for utilizing anautonomous tool having at least a portion formed from a dissolvablematerial in accordance with an embodiment of the present techniques.

FIG. 2 is an exemplary autonomous tool for use in tubular operations inaccordance with an embodiment of the present techniques.

FIG. 3 is a side view of an exemplary autonomous tool for a wellboreplugging operation in accordance with an embodiment of the presenttechniques.

FIG. 4 is a side view of an exemplary autonomous tool for a wellboreperforating operation in accordance with an embodiment of the presenttechniques.

FIG. 5 is an exemplary flow chart of a method for utilizing anautonomous tool having two or more actuatable tool components, whereinthe autonomous tool has at least a portion formed from a dissolvablematerial in accordance with an embodiment of the present techniques.

FIGS. 6A, 6B and 6C are a side view of a portion of a wellbore and thesubsurface formation near the wellbore for different stages ofdeployment of the autonomous tool in accordance with an embodiment ofthe present techniques.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments ofthe present techniques are described. However, to the extent that thefollowing description is specific to a particular embodiment or aparticular use of the present techniques, this is intended to be forexemplary purposes only and simply provides a description of theexemplary embodiments. Accordingly, the techniques are not limited tothe specific embodiments described below, but rather, include allalternatives, modifications, and equivalents falling within the truespirit and scope of the appended claims.

Unless otherwise explained, all technical and scientific terms usedherein have the same meaning as commonly understood by one of ordinaryskill in the art to which this disclosure pertains. The singular terms“a,” “an,” and “the” include plural referents unless the context clearlyindicates otherwise. Similarly, the word “or” is intended to include“and” unless the context clearly indicates otherwise. The term“includes” means “comprises.” All patents and publications mentionedherein are incorporated by reference in their entirety, unless otherwiseindicated. In case of conflict as to the meaning of a term or phrase,the present specification, including explanations of terms, control.Directional terms, such as “upper,” “lower,” “top,” “bottom,” “front,”“back,” “vertical,” and “horizontal,” are used herein to express andclarify the relationship between various elements. It should beunderstood that such terms do not denote absolute orientation (e.g., a“vertical” component can become horizontal by rotating the device). Thematerials, methods, and examples recited herein are illustrative onlyand not intended to be limiting.

As used herein, the terms “ceramic” or “ceramic material” may includeoxides such as alumina and zirconia. Specific examples include bismuthstrontium calcium copper oxide, silicon aluminum oxynitrides, uraniumoxide, yttrium barium copper oxide, zinc oxide, and zirconium dioxide.“Ceramic” may also include non-oxides such as carbides, borides,nitrides and silicides. Specific examples include titanium carbide,silicon carbide, boron nitride, magnesium diboride, and silicon nitride.The term “ceramic” also includes composites, meaning particulatereinforced combinations of oxides and non-oxides. Additional specificexamples of ceramics include barium titanate, strontium titanate,ferrite, and lead zierconate titanate.

As used herein, “dissolvable material” means materials that dissolve orbreak apart under certain tubular condition. The dissolvable materialsmay include the classes of polymers, metals or composites that dissolveor break apart under certain tubular conditions (e.g., certain pressureranges, certain temperature ranges and certain chemistry ranges, such asconcentrations of certain compounds that may be present within awellbore) and rendering the material small enough to not interfere withtubular operations. For example, if the dissolvable material is apolymer material, it may undergo a hydrolysis reaction with the reactionproducts going into solution (e.g., by the polymer material interactingwith formation water, which may be in a specific range or concentrationfor the water). As another example, if the dissolvable material is ametal, it may undergo galvanic reactions with the resulting productsbeing reduced in size and/or going into solution. Further, as yetanother example, if the dissolvable material is a polymer material, itmay undergo a reaction with the reaction products going into solutionwithin a certain temperature range. By way of example, a ball sealer maybe fabricated from a dissolvable material, which may be configured todissolve in five days, five weeks, or five months.

As used herein, the term “fluid” refers to gases, liquids, andcombinations of gases and liquids, as well as to combinations of gasesand solids, combinations of liquids and solids, and combinations ofgases, liquids, and solids.

As used herein, the term “formation” refers to any definable subsurfaceregion. The formation may contain one or more hydrocarbon-containinglayers, one or more non-hydrocarbon containing layers, an overburden,and/or an underburden of any geologic formation.

As used herein, the term “friable” means any material that may becrumbled, powderized, fractured, shattered, or broken into pieces, oftenpreferably small pieces. The term /to “friable” also includes frangiblematerials such as ceramic. It is understood, however, that in many ofthe apparatus and method embodiments disclosed herein, componentsdescribed as friable, may alternatively be comprised of drillable ormillable materials, such that the components are destructible and/orotherwise removable from within the wellbore.

As used herein, the term “gas” refers to a fluid that is in its vaporphase at 1 atmosphere (atm) and 15° C. (Celsius).

As used herein, the term “hydrocarbon” refers to an organic compoundthat includes primarily, if not exclusively, the elements hydrogen andcarbon. Hydrocarbons may also include other elements, such as, but notlimited to, halogens, metallic elements, nitrogen, oxygen, and/orsulfur. Hydrocarbons generally fall into two classes: aliphatic, orstraight chain hydrocarbons, and cyclic, or closed ring hydrocarbons,including cyclic terpenes. Examples of hydrocarbon-containing materialsinclude any form of natural gas, oil, coal, and bitumen that can be usedas a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions or at ambient conditions (15° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, coalbedmethane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product ofcoal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the term “millable” is somewhat synonymous with the term“drillable,” and both refer to any material that with the proper toolsmay be drilled, cut, or ground into pieces within a wellbore. Suchmaterials may include, for example, aluminum, brass, cast iron, steel,ceramic, phenolic, composite, and combinations thereof. The terms may beused substantially interchangeably, although milling is more commonlyused to refer to the process for removing a component from within awellbore while drilling more commonly refers to producing the wellboreitself.

As used herein, the term “oil” refers to a hydrocarbon fluid containingprimarily a mixture of condensable hydrocarbons.

As used herein, the terms “produced fluids” and “production fluids”refer to liquids and/or gases removed from a subsurface formation,including, for example, an organic-rich rock formation. Produced fluidsmay include both hydrocarbon fluids and non-hydrocarbon fluids.Production fluids may include, but are not limited to, oil, natural gas,pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbondioxide, hydrogen sulfide and water /to (including steam).

As used herein, the term “production casing” includes a liner string orany other tubular member fixed in a wellbore along a zone of interest.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

As used herein, the term “wellbore” refers to a hole or void in thesubsurface made by drilling or insertion of a conduit into thesubsurface. A wellbore may have a substantially circular cross section,or other cross-sectional shapes. As used herein, the term “well”, whenreferring to an opening in the formation, may be used interchangeablywith the term “wellbore.”

As used herein, “tubular conditions” refers to the range of pressures,temperatures, and chemistry within a wellbore and/or tubular member,such as a conduit and/or pipe. For example, tubular conditions within awellbore typically include temperatures between 26° C. to 150° C. fortemperatures (Bottom Hole Temperatures) and pressures between 100 poundsper square inch (psi) and 25,000 psi. Further, the chemistry within atubular member and/or wellbore may include different quantities ofhydrocarbons, water (H₂0), carbon dioxide (CO₂), nitrogen (N₂) andhydrogen sulfide (H₂S). The water chemistry includes properties, such aspH, presence of dissolved ions like chlorides, sulfates, etc.

As used herein, the terms “zone” or “zone of interest” refers to aportion of a formation containing hydrocarbons. Alternatively, theformation may be a water-bearing interval.

Persons skilled in the technical field will readily recognize that inpractical applications of the disclosed methodology, it is partiallyperformed on a processor based device (e.g., on-board controller or alogic control device), typically a suitably programmed processor baseddevice. Further, some portions of the detailed descriptions which followare presented in terms of procedures, steps, logic blocks, processingand other symbolic representations of operations on data bits within acomputer or processor memory. These descriptions and representations arethe means used by those skilled in the data processing arts to mosteffectively convey the substance of their work to others skilled in theart. In the present application, a procedure, step, logic block,process, or the like, is conceived to be a self-consistent sequence ofsteps or instructions leading to a desired result. The steps are thoserequiring physical manipulations of physical quantities. Usually,although not necessarily, these quantities take the form of electricalor magnetic signals capable of being stored, transferred, combined,compared, and otherwise manipulated in a process based device.

It should be borne in mind, however, that all of these and similar termsare to be associated with the appropriate physical quantities and aremerely convenient labels applied to these quantities. Unlessspecifically stated otherwise as apparent from the followingdiscussions, it is appreciated that throughout the present application,discussions utilizing the terms such as “processing” or “computing”,“calculating”, “comparing”, “determining”, “displaying”, “copying,”“identifying,” “storing,” “adding,” “applying,” “executing,”“maintaining,” “updating,” “creating,” “constructing” “generating” orthe like, refer to the action and processes of a process based device,or similar electronic computing device, that manipulates and transformsdata represented as physical (electronic) quantities within the computersystem's registers and memories into other data similarly represented asphysical quantities within the processor based device memories orregisters or other such information storage, transmission or displaydevices.

Autonomous tools are configured to be dropped or pumped into a wellbore.The majority of the bulk material may be made from ceramic or some otherfrangible material, as described in U.S. Patent Application PublicationNo. 20130062055, which is incorporated by reference herein in itsentirety. Upon completion of the desired tubular operation or activity(e.g., perforating, cutting, setting plug, etc.), the autonomous toolmay break apart and create small chards of material that do not obstructthe wellbore. These chards then settle to the bottom of the wellbore,are pumped into the formation, or flow out of the well duringproduction. Yet, some components or parts may not be made from ceramicmaterials economically. These materials may be made from materials thatdo not break-up appropriately or have the potential to plugperforations. Further, in horizontal sections of the wellbore, thechards may settle over the lower portion of the wellbore, which mayhinder access to this portion of the wellbore. Accordingly, the numberof autonomous tool used in a single well increases potential issues byaccumulating a significant amount of debris within the wellbore.

Beneficially, the use of dissolvable materials in the autonomous toolsmay enhance economics and performance by reducing the cost andincreasing the functionality of the autonomous tool, enhancing reliablyby ensuring that the autonomous tool fragments are ultimately reducedsufficiently in size and/or eliminate the need for explosives to reducethe tool to fragments, which may be desirable in locations where thereare restrictions on the use of explosives. Functionality may also beenhanced by use of less dense materials, which enhance the flow or pumpdown characteristics of the autonomous tool. Lighter materials or anoverall less dense autonomous tool may flow in the “center line” offluids under turbulent conditions. This condition significantly improvesthe timing and reliability of estimation of the tool on target. Also,the synergies between using two or more materials together in anautonomous tool may further enhance the operations. For example, usingdissolvable materials for certain parts or components may be moreeconomical as compared to frangible materials because it may lessen thecost of manufacture significantly. Also, if the parts or components havethe ability to dissolve into wellbore fluids, the accumulation ofmaterials in the well may be lessened or mitigated. The integration ofthese materials may also provide enhanced production capability becausethe flow paths that provide fluid communication with the formation arenot obstructed (e.g., tubular conduits and/or the perforation passagesare not restricted to flow or lessen pressure drops). In addition,materials that may plug off flow control devices may be removed from thewell by solution or captured by being pumped back into the formation(e.g., during flow back operations), which further lessens operatingexpenses.

The present techniques involve the use of autonomous tools that arefabricated to have at least a portion made of a dissolvable material.Accordingly, the present techniques disclose processes and systems forperforming tubular operations (e.g., well operations) in subsurfaceformations in an enhanced manner. As noted above, the use of autonomoustools involves deploying autonomous tools into the wellbore that are notretrieved or guided by surface based equipment (e.g., wireline or othersuch manual guidance equipment). As such, the autonomous tools have tobe transformed after the tubular operation is performed to not interfereor to lessen interference with subsequent tubular operations. While theautonomous tool may be fabricated from other materials, such asfrangible and/or friable materials, at least a portion of the autonomoustool may be fabricated from a dissolvable material in the presenttechniques. The frangible and/or friable materials may become tinyshards when broken-up with explosives and may be pumped into theformation, flow back to surface, or settle to the bottom of the wellwithout economic impact or impact on future well intervention operations(e.g., production logging), while the dissolvable materials may bedissolve into the fluids within the wellbore.

The dissolvable materials include classes of polymers, metals orcomposites that dissolve or break apart under “friable action” (e.g.,performed by the tool) as well as under tubular conditions, which mayrender the pieces small enough so as not to interfere with tubularoperations. For example, the dissolvable materials may includepolylactic acid (PLA), polyglycolic acid (PGA), polydioxone (PDO),polycaprolactone (PCL), alloys and other polymers or dissolvable metalmaterials. The dissolvable materials, which may be non-frangiblematerials, may dissolve naturally over time at tubular conditions.Further, the dissolvable materials (e.g., dissolvable polymers) may beprovided in a variety of strengths and decomposition capabilities formany different applications. For example, the dissolvable material maydissolve at different rates and/or may dissolve in different tubularconditions (e.g., as a result of exposure to concentrations of aspecific compound, exposure to certain temperatures, or exposure tocertain pressures).

The autonomous tool may include one or more components with eachcomponent being a single element or including one or more parts. Inparticular, the one or more components may include a control logicsystem or component (e.g., on-board controller), a location or depthdetermination device or component, an actuatable tool component, such asa perforating component, a shockwave component, a pipe cuttingcomponent, a dump bailing component, a setting tool component to setbridge plugs, and/or any other suitable components. One or more partsand/or one or more components of the autonomous tools may be fabricatedfrom the dissolvable material. For example, circuit boards, seals,and/or environmental protection casing may be fabricated from thedissolvable material. As another example, a setting tool component forbridge plug application or the crossover connections to a jet cuttingcharge for casing or tubing may be fabricated from the dissolvablematerial. Also, the dissolvable material may be used to fabricatecontrol circuit boards for control logic, and/or parts of the safetycontrol systems or components, such as the housing for addressableswitches. At least a portion of the autonomous tool may include one ormore parts in a component, may include one or more components and evenmay include fabricating the entire autonomous tool from the dissolvablematerial. For example, the autonomous tools may include a ceramic toolbody and the threaded connectors made of dissolvable material (e.g., ametal material or polymer). As a further example, the dissolvablematerial may be used to fabricate seals and/or sealing devices, such asO-rings, gaskets, bulk heads, etc. In addition, the dissolvable materialmay be used for connection devices between dissimilar materials.

In one or more embodiments, the autonomous tool may be utilized in amethod to enhance the tubular operations. For example, an autonomoustool may be fabricated, wherein at least a portion of the autonomoustool is from dissolvable material. Then, the autonomous tool may beconfigured to perform one or more tubular operations, which may involvecoupling various components together and programming the differentcomponents to perform the one or more tubular operations. Onceconfigured, the autonomous tool is deployed into the wellbore. Thedeploying the autonomous tool may include pumping, using gravitationalpull, using a tractor, or any combinations thereof. Once deployed, theautonomous tool may perform the tubular operation. Following theperformance of the tubular operation, at least a portion of theautonomous tool may dissolve based on the tubular conditions (e.g.,wellbore conditions). Then, hydrocarbons may be produced from thesubsurface region.

To further enhance tubular operations, the autonomous tool may includevarious components coupled together and configured to activate within apredetermined sequence of tubular operations. For example, the two ormore autonomous components may be configured to be deployed as a singleautonomous tool. As an example, the autonomous tool may include anon-board controller (e.g., a logic control device or processorcontrolled device) that is combined with a perforating gun component anda bridge plug component. The on-board controller may be configured tomeasure speed and depth with a processor running an algorithm thatcalculates speed and depth for the perforating gun component and thebridge plug component. Once the perforating gun component reaches apre-determined location, the perforating gun component may initiate anaction, such as perforating the wellbore, and then the bridge plugcomponent may initiate an action, such as setting a bridge plug. In sucha configuration, a dissolvable material may be used to deploy anautonomous tool at a specific depth or after exposure to the conditionswithin the wellbore for a specific amount of time. In this manner, twoor more autonomous tool components may be deployed into the wellbore asa single autonomous tool (e.g., an autonomous assembly) and thedissolvable material may be utilized to maintain the specific sequentialorder of tubular operations (e.g., well operations) for the wellbore.

In one or more embodiments, the present techniques may be used to deploya single autonomous tool, which includes a set of two or more autonomoustool components. The single autonomous tool may perform multiple tubularoperations via a single deployment. For example, the autonomous tool maystimulate multiple target zones or regions via a single deployment ofthe autonomous tool. The autonomous tool may provide a mechanism forselective placement of each stimulation treatment for each individualzone to enhance well productivity. Also, the autonomous tool may providediversion between zones to ensure each zone is treated per design andpreviously treated zones are not inadvertently damaged. Further, theautonomous tool may provide a mechanism for stimulation treatments to bepumped at high flow rates to facilitate efficient and effectivestimulation. As such, the autonomous tool may enhance tubularoperations, such as multi-zone stimulation techniques and the associatedhydrocarbon recovery from subsurface formations that contain multiplestacked subsurface intervals. With the ability to use dissolvablematerial in the autonomous tool string, non-friable parts may act as“shock absorbers” or bulk heads protecting other friable parts frombeing inadvertently affected by the need to break apart or “fry” asection of the component or tool at individual stages of operationduring the operation of the autonomous tool within the wellbore. Anexample may include perforating multiple stages or zones separated bydistance in one run. As one perforating gun in a first perforating guncomponent is utilized (e.g., shot), a need exists to protect theremaining perforating gun components until each of the remainingperforating gun components have reached the depth or location forutilization. By utilizing dissolvable materials to separate theperforating gun components, multiple operations may be performed, whilenot contaminating the tubular with debris that is not “fry” or go intosolution over time.

As an example, the autonomous tool may include a packer componentdisposed on the lower or bottom of the autonomous tool and a perforatinggun component disposed above the packer component. Once the autonomoustool is dropped into the wellbore, an on-board controller of theautonomous tool may be configured to activate the packer component at aspecific depth or location. Once activated, the packer component mayform a plug within the wellbore and the on-board controller may beconfigured to activate the perforating gun component. The perforatinggun component may fire within the section of the wellbore to formperforations that may then be treated with sand. This process may berepeated by deploying another autonomous tool or deploying one or moreperforating gun components and one or more packer components from theremaining portion of the autonomous tool. Then, the series of plugs maydissolve over time and no milling operation is required and no separateoperation is needed to place plugs within the wellbore.

As yet another example, the autonomous tool may include an on-boardcontroller (e.g., a logic control device) that is combined with a firstperforating gun component and a second perforating gun component. Theon-board controller may be configured to calculate the location of thefirst perforating gun component and the second perforating guncomponent. Once the autonomous tool reaches a pre-determined location,the first perforating gun component may separate from the secondperforating gun component, which may initiate a timer for the respectiveperforating gun components to perform the perforating operations. Insuch a configuration, a dissolvable material may be used to couple theperforating gun components and may separate after exposure to theconditions within the wellbore (e.g., the tubular conditions) for aspecific amount of time. In this manner, two or more perforating guncomponents may be deployed into the wellbore as a single autonomous tool(e.g., an autonomous assembly) and the dissolvable material may beutilized to maintain the specific sequential order of tubular operations(e.g., well operations) for the wellbore. Further, each perforating guncomponent may include a ballast member, which is utilized to adjust themovement of the perforating gun component down the wellbore.

As an example, the present techniques may be utilized with multiple zonestimulation techniques, such as Just-In-Time-Perforating™ (“JITP”)process, as described in U.S. Pat. No. 6,543,538, which is incorporatedby reference herein in its entirety. In these techniques, the processmay involve: using a perforating device, perforating at least oneinterval of one or more subterranean formations traversed by a wellbore;pumping treatment fluid through the perforations and into the selectedinterval without removing the perforating device from the wellbore;deploying or activating an item or substance in the wellbore toremovably block further fluid flow into the treated perforations; andrepeating the process for at least one more interval of the subterraneanformation. Using dissolvable materials for the JITP components maylessen recovery operations of the tool string.

Further, in other embodiments, the autonomous tool may include ashockwave component. The shockwave component may be a fabricated toolcomponent, as described in U.S. Patent. Ser. Nos. 62/262,034,62/262,036, 62/263,069, which are each incorporated by reference hereinin their entirety. The shockwave component may include a collar locatorsystem, one or more rope socket devices, one or more primer cord carrierdevices, one or more addressable switches, one or more connector subsand one or more sealing devices, one or more setting tool parts to setbridge plugs, and/or any other suitable parts. The use of dissolvablematerials in the shockwave component provides a mechanism to mitigatethe problem of having to recapture the tool. For example, if one or moreparts of shockwave components are at least partially fabricated fromdissolvable materials, which may also include frangible or friablematerials as well, any shards that do not dissolve may be pumped outinto the formation, flow back to surface, or settle to the bottom of thewell without economic impact to production or impact on future tubularoperations. The use of dissolvable material may be used in thefabrication of a carrier bar, an addressable switch sub, a rope socketand other such parts. The dissolvable materials (e.g., polymers) mayinvolve a variety of strengths and decomposition capabilities for manydifferent applications.

Beneficially, the present techniques provide a more efficient completionprocess. First, the use of autonomous tools remove the reliance onwireline-conveyed or tubing-conveyed tools, which are difficult to runthough a lubricator and limit the pump rates. Further, without thesurface equipment (e.g., cranes, wireline equipment and coil tubingunits), the expense of the operation and risks to personnel may belessened, which lessens the overall economics of extraction operations.Further, various risks are avoided or mitigated by changing the overallapproach because wireline failures and/or subsequent fishing operationsmay not be utilized with certain embodiments of the present techniques.

In one or more embodiments, the present techniques may include anautonomous tool that includes various components with at least a portionof the autonomous tool being fabricated from a dissolvable material. Forexample, the autonomous tool may include an actuatable tool component; alocation component for sensing the location of the actuatable toolcomponent within a wellbore or other tubular member based on a physicalsignature (e.g., a pressure sensor and/or casing collar locator); and anon-board controller configured to transmit an actuation signal to theactuatable tool component when the location component has determinedthat a selected or predefined location of the actuatable tool componenthas been reached based on the physical signature. The actuatable toolcomponent is configured to be actuated to perform a well or tubularoperation in response to the actuation signal. The actuatable toolcomponent, the location component, and the on-board controller aretogether dimensioned and arranged to be deployed in the wellbore orother tubular member as an autonomous tool. The tubular member may be awellbore constructed to produce hydrocarbon fluids or a pipelinetransporting fluids. Further, the actuatable tool component, thelocation component, and the on-board controller may be coupled togetherand/or disposed within a housing. The housing and/or the couplingmechanism may include a frangible material or a dissolvable material.The actuatable tool component may be, for example, a fracturing plug, abridge plug, a cutting tool, a casing patch, a cement retainer, or aperforating gun.

In certain embodiments, the autonomous tool may include a locationcomponent (e.g., location controller or position controller). Thelocation component may be a separate component from an on-boardcontroller, or may be integrally included within the on-boardcontroller. The location component may be configured to determine thelocation of the autonomous tool or a component within the wellbore ortubular member (e.g., to sense or identify the location of theactuatable tool or a component within a tubular member). The locationcomponent may determine the location or position within the tubularmember (e.g., within the casing string of the wellbore) based on aphysical signature provided along the tubular member. For example, thelocation component may be a casing collar locator, and the physicalsignature may be formed by the spacing of collars along the tubularmember. As the different casing collars are identified by the collarlocator, the location of the autonomous tool is determined relative to apredetermined casing collar location. As another example, the locationcomponent may be a radio frequency antenna, and the physical signaturemay be formed by the spacing of identification tags along the tubularmember. As the identification tags are identified by the radio frequencyantenna, the location of the autonomous tool is determined relative to apredetermined identification tag location. Further, as yet anotherexample, the location component may be a pressure sensor, and thephysical signature may be formed by the pressure changes within thetubular member. As the pressure reaches a predetermined threshold, thelocation of the autonomous tool is determined relative to apredetermined pressure identifier. Moreover, the location component mayinclude two or more sensing devices spaced apart along the autonomoustool, which may be two of more of casing collar locators, radiofrequency antenna, pressure sensor and any combination thereof. As aspecific example, for two sensing devices, the first sensing device maybe disposed lower than the second sensing device relative to thedirection of travel into the tubular member. The first sensing devicemay be referred to as the lower sensing device and the second sensingdevice may be referred to as the upper sensing device. In thisconfiguration, the signatures formed by the different sensing devicesmay be used to determine the location of the autonomous tool and/or tovalidate the location of the autonomous tool (e.g., by comparing thedetermined locations).

In other embodiments, the autonomous tool may include an on-boardcontroller, as one of the components. The on-board controller may beconfigured to transmit or send an actuation signal to the actuatabletool component when the location component has identified the selectedlocation within the tubular member and/or when the on-board controllerhas determined that a specific time period has elapsed. The on-boardcontroller may include a clock or timing mechanism that determines theamount of time that elapses between sensing different signatures (e.g.,sensing different tags, collars, wireless transmitter signals or depths)as the autonomous tool traverses the tubular member. The autonomoustool, or specifically the on-board controller, may be configured orprogrammed to determine the velocity of the autonomous tool at a giventime based on the distance between signatures (e.g., comparing thesignature from the lower sensing device and the signature of the uppersensing device, or dividing the distance traveled between sensors by theelapsed time between the signatures. The position of the autonomous toolmay then be determined by one or more of calculating the location of theautonomous tool relative to the signatures (e.g., tags as sensed byeither the lower or the upper sensing device), and calculating thevelocity of the autonomous tool as a function of time.

The actuatable tool component of the autonomous tool may includedifferent components to perform specific tubular operations. Forexample, the actuatable tool component may be a perforating guncomponent. The perforating gun component may be fabricated from at leasta portion of dissolvable material and may be configured to fire shots(e.g., from a detonation device) along the selected location to produceperforations into the associated casing string and cement sheath at thatselected location. As another example, the actuatable tool component maybe a ball sealer component. The ball sealer component may be configuredto release a plurality of ball sealers to block flow through anyperforations at a selected locations. The ball sealer component may beconfigured to release the ball sealers before the perforating operationsare performed or simultaneously therewith. In yet another example, theactuatable tool component may be a fracturing plug component. Thefracturing plug component may include a fracturing plug having anelastomeric element for creating a fluid seal upon being actuated. Thefracturing plug component may also be configured to detect a selectedlocation along the wellbore for setting and may be configured to actuateone or more slips and a sealing element are together actuated to set thefracturing plug assembly. Further still, in another example, theactuatable tool component may be a setting component that include a setof slips for holding the autonomous tool in the wellbore. In thisconfiguration, the setting component may be configured to activate theslips to be set in the wellbore at the selected location. Moreover, theactuatable tool component may be a fracturing plug, a shockwavecomponent, a cement retainer, or a bridge plug. The autonomous tool alsohas a setting tool for setting the autonomous tool.

In yet other embodiments, the present techniques may include methods forperforming tubular operations (e.g., wellbore completion operation) witha working line that does not provide any communication between theautonomous tool and surface equipment. As an example of thisconfiguration, the wellbore is constructed to produce hydrocarbon fluidsfrom a subsurface formation or to inject fluids into a subsurfaceformation. The method includes deploying an autonomous tool into thewellbore, which may be deployed via a working line (e.g., a slickline, awireline, or an electric line). The autonomous tool includes at least aportion of it being fabricated from a dissolvable material. Further, themethod may include removing the working line after the autonomous toolis set in the wellbore. Moreover, the autonomous tool may include alocation component for sensing the location of the actuatable toolcomponent within the wellbore based on a physical signature providedalong the wellbore. Also, the on-board processor may be configured totransmit or send an actuation signal to the actuatable tool componentwhen the location component has determined a selected location of theactuatable tool component based on the physical signature. Theactuatable tool component is configured to perform the tubular operationin response to the actuation signal. The present techniques may befurther understood with reference to the FIGS. 1 to 6C below.

FIG. 1 is an exemplary flow chart 100 of a method for utilizing anautonomous tool having at least a portion formed from a dissolvablematerial in accordance with an embodiment of the present techniques. Inthis flow chart 100, the method may be used to autonomously performtubular operations. In particular, the method utilizes an autonomoustool having at least a portion formed from a dissolvable material. Thedissolvable material may provide shock resistant connections, pressurebulk heads, fixtures and/or electrical boards with enhanced shockresistance, for example. The method provides potentially lower cost,enhances reliably by ensuring tool fragments are reduced to acceptablesize or dissolved, provides an alternative to ceramic materials (e.g.,which are difficult to fabricate components, such as joints betweencomponents).

The method begins at block 102. In block 102, an autonomous tool isfabricated having at least a portion of the autonomous tool being formedfrom dissolvable material. The autonomous tool may include an actuatabletool component (e.g., perforating gun component, ball sealer component,fracturing plug component, setting component, fracturing plug component,cement retainer component, bridge plug component, shockwave componentand any combination thereof), a location component and an on-boardcontroller. Further, the autonomous tool may also include a housing thatis utilized to enclose one or more components and to isolate one or morecomponents from fluids within the tubular member. Also, the dissolvablematerial may include materials, such as polylactic acid (PLA),polyglycolic acid (PGA), polydioxone (PDO), polycaprolactone (PCL),alloys, and the like. At block 104, the autonomous tool is configured toperform a tubular operation. Configuring the autonomous tool may includeprogramming the components to perform specific operations or functions(e.g., perform the tubular operation at a specific location) or within aspecific time period, to determine the location of the autonomous tooland/or to actuate the actuatable tool component. Further, configuringthe autonomous tool may include coupling various components together tocommunicate with each other and/or to be secured together to form theautonomous tool.

Once the configuration is completed, the autonomous tool may be used inthe tubular member to perform the tubular operations, as shown in blocks106, 108 and 110. At block 106, the autonomous tool is deployed into thetubular member. The deployment of the autonomous tool may includepumping, using gravitational pull, using a tractor, or combinationsthereof. Further, the deployment may involve the use of a working line(e.g., a slickline, a wireline, or an electric line). At block 108,autonomous tool performs the tubular operation. The tubular operationmay include perforating, cutting, setting a plug or seal, and other welloperations. Then, once the tubular operation is performed, at least aportion of the autonomous tool dissolves, as shown in block 110. Thedissolving of the at least a portion of the autonomous tool may involvedissolving parts, fixtures, connections, tubular, bulk heads and/orparts of an actuating tool component. Further, at least a portion of theremaining autonomous tool may be broken apart to create small chards ofmaterial, which are not intended to obstruct the tubular member. Thechards may fall to bottom of the tubular member, may be pumped out ofthe tubular member (e.g., into the formation), and/or may flow out ofthe well during production. The at least a portion of the remainingautonomous tool may be fabricated from a frangible material. Thefrangible material may include ceramic, phenolic, composite, cast iron,brass, aluminum, or combinations thereof.

Once the tubular operation is completed, the hydrocarbons may be managedfrom the tubular member, as shown in block 112. This management mayinclude resuming passing hydrocarbons through a pipeline or furtherprocessing the hydrocarbon downstream of the tubular member. Further,the management of the hydrocarbons may include extracting or producingthe hydrocarbon from the subsurface formation and the well.

Beneficially, the present techniques may lessen operating costs and maylessen operational delays in performing the tubular operations. Forexample, the tubular operations may not involve operations utilized tocapture tools, recover tools and/or couple or decouple tools from awireline, as performed with conventional wireline based tubularoperations. Further, as another example, the present techniques may beutilized to lessen the equipment utilized in the tubular operations,such as hollow steel carriers, depth location equipment and connectionsused to attach devices or tools to a wireline umbilical and/or detachdevices or tools to a wireline umbilical.

As may be appreciated, the present techniques may include autonomoustools that are have one or more components secured together andconfigured to communicate with each other. The components may includeprocessor based devices in certain configurations, such as an on-boardcontroller and a logic control device, which are configured to performcertain functions. Accordingly, the components, methodologies, and otheraspects of the present techniques can be implemented as software,hardware, firmware or any combination of the three. Of course, wherevera component or subcomponent of the present techniques is implemented assoftware, the component can be implemented as a standalone program, aspart of a larger program, as a plurality of separate programs, as astatically or dynamically linked library, as a kernel loadable module,as a device driver, and/or in every and any other way known now or inthe future to those of skill in the art of computer programming.Additionally, the present techniques are in no way limited toimplementation in any specific operating system or environment.

For example, FIG. 2 is an exemplary autonomous tool 200 for use intubular operations in accordance with an embodiment of the presenttechniques. The autonomous tool may include an on-board controller 202that communicates with an actuatable tool component 204 and a locationcomponent 206. The components may communicate via a physical mechanisms(e.g., wires) or may communicate via wireless mechanisms (e.g., radiowave transmissions). Further, the autonomous tool 200 may also include ahousing 208 that is utilized to enclose one or more components, such ascomponents 202, 204 and 206 for this exemplary configurations. Thehousing 208 may be utilized to isolate components from fluids within thetubular member.

The on-board controller 202 may be configured to manage the tubularoperations. The on-board controller 202 may include a processor, memoryaccessible by the processor and a set of instructions stored on thememory that are configured to communicate with the other components,such as actuatable tool component 204 and a location component 206, toreceive location data and provide instructions, such as notifications orsignals to the other components. The on-board controller 202 may beconfigured to calculate from the location data, depth, time and/orvelocity when the actuatable tool component 204 should be activated ormay be configured to deploy additional actuatable tool component, ifnecessary. For example, the on-board controller 202 may be configured totransmit or send an actuation signal to the actuatable tool component204 when the location component 206 has identified the selected locationwithin the tubular member (e.g., from a wireless transmitter within thetubular member) and/or when the on-board controller 202 has determinedthat a specific time period has elapsed. The on-board controller 202 mayinclude a clock or timing mechanism (not shown) that determines theamount of time that elapses between sensing different signatures (e.g.,sensing different tags, collars, or depths) as the autonomous tooltraverses the tubular member. The on-board controller 202 may also beconfigured to calculate the velocity of the autonomous tool at a giventime based on the distance between location data or signatures (e.g.,comparing the signature from the same sensor at two locations orcomparing the data from two or more sensors, and then dividing thedistance traveled between location data (e.g., distance travelled) bythe elapsed time between the signatures.

The actuatable tool component 204 may be configured to perform one ormore tubular operations. For example, the actuatable tool component 204may include perforating gun component, ball sealer component, fracturingplug component, setting component, fracturing plug component, cementretainer component, bridge plug component and any combination thereof,for example.

The location component 206 may determine or recognize the location ofthe autonomous tool within the tubular member. The location component206 may be a separate component from an on-board controller 202, or maybe integrally included within or as part of the on-board controller 202.The location component 206 may include a processor, memory accessible bythe processor and a set of instructions stored on the memory that areconfigured to communicate with the other components, such as on-boardcontroller 202, and one or more sensors, such as first sensor 210 andsecond sensor 212, to receive location data and to provide instructions,such as notifications or signals to the other components, such ason-board controller 202. The location component 206 may utilize alocation detection technology to determine the location of theautonomous tool or one of the respective components based on thelocation detection technology (e.g., sensing different tags, collars,velocity, time and/or depths). As an example, the location component 206may be configured to determine the location or position within thetubular member (e.g., within the casing string of the wellbore) based ona physical signature provided from identification tags along the tubularmember, or by detecting or identifying casing joints or casing collarswithin the tubular member; by identifying radio frequency tags along thetubular member or by determining the depth of the autonomous tool basedon pressure within the tubular member. For example, the locationcomponent 206 may be configured to receive location data from sensors210 and 212 and to determine the location based on that location data.As another example, the location component 206 may be configured toobtain location data that is pressure measurement data from the sensors210 and 212 and to determine the location based on the pressure withinthe tubular member at the location. Further, the location component 206may also include an accelerometer, which is configured to measureacceleration experienced during a freefall. The accelerometer, which mayinclude a gyroscope, may include multi-axis capability to detectmagnitude and direction of the acceleration as a vector quantity. Thelocation component 206 may be configured to calculate the location ofthe autonomous tool.

As an example, the on-board controller 202 may be a computing system,which may be utilized and configured to implement on or more of thepresent aspects. The computing system may include a processor; memory incommunication with the processor; and a set of instructions stored onthe memory and accessible by the processor, wherein the set ofinstructions, when executed, are configured to perform one or moreoperations that are pre-programed into the device. The dissolvablecomponents, which may include the mother board, clips and/or otherhardware, lessen any debris that has to be removed from the tubularmember for ongoing operations and lessen the potential for any negativeimpact to fluid conductivity for ongoing tubular operations.

FIG. 3 is a side view of an exemplary autonomous tool 300 as may be usedfor tubular operations within a wellbore. In this view, the autonomoustool 300 is a fracturing plug assembly, which may be used to perform thetubular operation in a wellbore completion. The autonomous tool 300 maybe deployed within a string of production casing, which is formed from aplurality of joints that are threadedly connected at collars. Theautonomous tool 300 is exposed to injection of fluids, which may beinclude high pressures and temperatures within the typical environmentof the wellbore completion. Also, the autonomous tool 300 may involve apre-actuated position (e.g., used for deployment) and an actuatedposition (e.g., used once actuated). Further, the autonomous tool 300forms a plug body and include various components, such as the locationcomponent 308, an on-board controller 310, and an actuatable toolcomponent, which includes an elastomeric sealing element 302, a set ofslips 304, and a setting tool 306.

The actuatable tool component includes different parts that performspecific functions for the autonomous tool. For example, the elastomericsealing element 302 is mechanically expanded in response to a shift in asleeve or other means as is known in the art. The slips 304 also rideoutwardly from the body along wedges (not shown) spaced radially aroundthe outer portion of the autonomous tool 300. Preferably, the slips 304are also urged outwardly along the wedges in response to a shift in thesame sleeve or other means as is known in the art. The slips 304 extendradially to “bite” into the tubular member, such as the casing, whenactuated, securing the autonomous tool 300 in position. The setting tool306 actuates the slips 304 and the elastomeric sealing element 302 andtranslates them along the wedges to contact the surrounding casing. Inthe actuated position, the elastomeric sealing element 302 is expanded,as shown along the arrow 312, into sealed engagement with thesurrounding production casing (not shown), and the slips 304 are alsoexpanded into mechanical engagement with the surrounding productioncasing (not shown). The sealing element 302 has a sealing ring, whilethe slips 304 have grooves or teeth that interact with the innerdiameter of the casing.

The location component 308 is configured to sense or identify thelocation of the autonomous tool 300 within the production casing.Accordingly, the location component 308 may be configured to detectcollars, object, tags or pressures within the wellbore and may beconfigured to generate a signature associated with the location of theautonomous tool 300 (e.g., depth signals in response to the determinedlocation). For example, the location component 308 may be a casingcollar locator that senses the location of the casing collars as itmoves down the production casing; a radio frequency detector thatdetects radio frequency identification tags; a pressure sensor thatdetects pressures within the wellbore; and/or any combination of thesedifferent techniques. As another example, the location component 308 mayinclude two or more of these techniques to provide verification orredundancy for the location identification. In particular, the locationcomponent 308 may include a casing collar locator and a pressure sensorthat are used to compare the respective locations that may be identifiedwithin the wellbore.

The on-board controller 310 is utilized to manage the tubular operation.For example, the on-board controller 310 is configured to process thedepth signals received from the location component 308. In oneconfiguration, the on-board controller 310 may be configured to comparethe received depth signals with a pre-determined signature associatedwith one or more objects. The predetermined signature may be apreviously performed casing collar log, which is performed beforedeploying the autonomous tool 300 to determine the spacing of the casingcollars; may be a diagram providing information concerning the spacingof tags; and/or may be a diagram of predetermined pressure measurements.Then, the depth of the autonomous tool 300 may be calculated based atleast partially on the comparison. Further, the on-board controller 310is configured to transmit a signal to activate the actuatable toolcomponent when it determines that the autonomous tool or specificallythe component has reached a particular depth or predetermined location.As an example, the activation of the autonomous tool 300 may includesending signals to the setting tool 306 to stop moving the autonomoustool through the tubular member, and to set the slips 304 and theelastomeric sealing element 302 in the tubular member at the desireddepth or location.

FIG. 4 is a side view of an exemplary autonomous tool 400 for a wellboreperforating operation in accordance with an embodiment of the presenttechniques. Similar to FIG. 3, the autonomous tool 400 may be deployedwithin a string of casing, which is formed from a plurality of jointsthat are threadedly connected at collars. The autonomous tool 400, whichmay include a perforating gun and other associated equipment, is exposedto various fluids within the wellbore, which may be include highpressures and temperatures within the typical environment of thewellbore. Also, the autonomous tool 400 may involve a pre-actuatedposition (e.g., used for deployment) and an actuated position (e.g.,used once actuated). In particular, the autonomous tool 400 may includevarious components, such as a first location component 404 and a secondlocation component 408, an on-board controller 410, and an actuatabletool component, which includes a fishing neck 402, a perforating gun406, and a ball sealer carrier 412.

The actuatable tool component may be parts for a perforating gunassembly that is configured to form perforations through the tubularmember and portions of the surrounding formation. The fishing neck 402may be dimensioned and configured to function as the male portion to amating downhole fishing tool (not shown). The fishing neck 402 providesa mechanism to retrieve the autonomous tool 400 if it becomes stuck inthe casing or fails to detonate. The perforating gun 406 may be a selectfire gun that fires, for example, 16 shots. The perforating gun 406 hasan associated charge that detonates to cause shots to be fired from theperforating gun 406 into the surrounding casing, as shown by arrow 414.The perforating gun 406 may include one or more shaped chargesdistributed along the length of the perforating gun 406 and orientedaccording to desired specifications. The charges are preferablyconnected to a single detonating cord to ensure simultaneous detonationof all charges. Examples of suitable perforating guns include the FracGun™ from Schlumberger, and the G-Force® from Halliburton. Further, theball sealer carrier 412 may be disposed at the lower portion of theautonomous tool 400. The ball sealer carrier 412 may be configured torelease the ball sealers (not shown) when the perforating gun 406 isactuated. Alternatively, the ball sealer carrier 412 may be configuredto release the ball sealers (not shown) when a timer on the on-boardcontroller 410 has elapsed a period of time (e.g., shortly before theperforating gun 406 is fired, concurrently therewith or simultaneouslytherewith). The released ball sealers may be used to seal perforationsthat have been formed at a lower depth or location in the wellbore.These ball sealers may be fabricated from the dissolvable material.

Similar to the location component 308 of FIG. 3, the first locationcomponent 404 and the second location component 408 may operate in asimilar manner. The location components 404 and 408 may determine thelocation of the autonomous tool 400 and generate one or more depthsignals in response. While one location component may be utilized, theautonomous tool 400 may include two location components, as a furtherenhancement to the tubular operations. The use of two locationcomponents may be utilized to verify the location between the firstlocation component 404 with the second location component 408 or tocalculate a combined location from the two location components 404 and408. Further, the location component 404 and 408 may utilize the samelocation techniques (e.g., casing collar locators; radio frequencydetectors or pressure sensors) or may be a combination of differentlocation techniques. For example, if the tubular operation involves moreprecision, the casing collar locator or radio frequency detector may bethe first location component 404, while the pressure sensor may be thesecond location component 408.

Also, the on-board controller 410 may operate in a similar manner to theon-board controller 310 of FIG. 3. The on-board controller 410 mayprocess the depth signals generated by one or more of the locationcomponents 404 and 408 using appropriate logic and power units. In oneconfiguration, the on-board controller 410 may compare the generateddepth signals with a pre-determined physical signature, as discussedabove. Further, the on-board controller 410 may be configured toactivate the actuatable tool component when it determines that theautonomous tool 400 has reached at a depth that is the selected orpredetermined location, which is performed using appropriate on-boardprocessing. As an example, the on-board controller 410 may activate adetonating cord that ignites the charge associated with the perforatinggun component 406 to initiate the perforation of the production casingat a desired depth or location. Further, the on-board controller 410 mayactivate the ball sealer carrier 412 to release the ball sealers (notshown) prior to igniting the detonating cord for the perforating guncomponent 406 or at the same time the detonating cord is ignited. Theactuation of the actuation tool component may be result in thedestruction of the autonomous tool, which may be fabricated form atleast a portion of dissolvable material and the remaining portion may befabricated from a friable material. As an example, the detonation mayresult in the materials that the autonomous tool 400 is fabricated frombecoming a part of the proppant mixture injected into fractures in alater completion stage.

To further enhance the process, a single autonomous tool may include twoor more actuatable tool components to perform two or more tubularoperations with a single deployment. For example, two or more actuatabletool components may be configured to deploy at different locations andmay be configured to delay activation to perform a specific sequence oftubular operations. By way of example, FIG. 5 is an exemplary flow chart500 of a method for utilizing an autonomous tool having two or moreactuatable tool components, wherein the autonomous tool has at least aportion formed from a dissolvable material in accordance with anembodiment of the present techniques. In this flow chart 500, the methodmay be used to autonomously perform multiple tubular operations in aspecific sequence. In particular, the method utilizes an autonomous toolhaving two or more actuatable tool components, wherein each of two ormore actuatable tool components perform a specific tubular operations.

The method begins at block 502. In block 502, an autonomous tool isfabricated having two or more actuatable tool components, which are eachconfigured to perform a respective tubular operation. At least a portionof the autonomous tool is formed from strategic placement of dissolvablecomponents for the desired effect. The two or more actuatable toolcomponent may include perforating gun component, ball sealer component,fracturing plug component, setting component, fracturing plug component,cement retainer component, bridge plug component and any combinationthereof. The autonomous tool may also include one or more locationcomponents and one or more on-board controllers, which may be dedicatedto each of the actuatable tool components or utilized for the actuatabletool components. Further, the autonomous tool may also include a housingthat is utilized to enclose one or more components and to isolate one ormore components from fluids within the tubular member. At block 504, theautonomous tool is configured to perform the sequence of tubularoperations. Similar to block 104 of FIG. 1, the configuring theautonomous tool may include programming the components to performspecific operations or functions (e.g., perform the tubular operation ata specific location) or within a specific time period, to determine thelocation of the autonomous tool and/or to actuate the actuatable toolcomponent.

Once configured, the autonomous tool may be used in the tubular memberto perform the sequence of tubular operations, as shown in blocks 506,508, 510, 512, 514 and 516. At block 506, the autonomous tool isdeployed into the tubular member. Similar to block 106 of FIG. 1, thedeployment of the autonomous tool may include pumping, usinggravitational pull, using a tractor, or combinations thereof. At block508, autonomous tool determines if the first location has been reached.If the first location has not been reached, the autonomous toolcontinues to monitor the location within the tubular member. However, ifthe first location has been reached, the autonomous tool may actuate thefirst actuatable tool component, as shown in block 510. The actuatingthe first actuatable tool component may include detaching or separatingthe first actuatable tool component from the remaining actuatable toolcomponents (e.g., the second actuatable tool component). Then, theautonomous tool determines if the second location has been reached inblock 512. If the second location has not been reached, the autonomoustool continues to monitor the location within the tubular member.However, if the second location has been reached, the autonomous toolmay perform the sequence of tubular operations, as shown in block 514.This may involve actuating the second actuatable tool component. Forexample, the sequence of tubular operations may include the firstactuating tool component releasing ball sealers and then the secondactuating tool component perforating the tubular member at the secondlocation. Then, once the sequence of tubular operations are performed,the at least a portion of the autonomous tool dissolves, as shown inblock 516. The dissolving of the at least a portion of the autonomoustool may be performed in a similar manner to block 110 of FIG. 1.

Once the sequence of tubular operations are completed, the hydrocarbonsmay be managed from the tubular member, as shown in block 518. Thismanagement may include resuming passing hydrocarbons through a pipelineor further processing the hydrocarbon downstream of the tubular member.Further, the management of the hydrocarbons may include extracting orproducing the hydrocarbon from the subsurface formation and the well.Beneficially, the time involved in the production of hydrocarbons may belessened to enhance the economics of the well investment anddevelopment.

By way of example, the autonomous tool may include a configuration ofperforating gun components to perforate multiple target zones or regionsand set a bridge plug components to isolate previously treated zones viaa single deployment of the autonomous tool. This configuration may besimilar to conventional plug and perforate operation, but without theuse of wireline and its associated equipment. Accordingly, thisconfiguration may lessen costs and lessen down time associated withspooling in, pump down, and removal of the wire and tool string througha lengthy lubricator. Beneficially, this may lessen total time onlocation, which lessens the associated costs. Further, the sooner thefracture fluids can be removed from the formation, the less negativeimpact the fracture fluids may have on the formation, which enhanceproduction.

FIGS. 6A, 6B and 6C are a side view 600, 620 and 640 of a portion of awellbore and the subsurface formation near the wellbore for variousstages of deployment of the autonomous tool in accordance with anembodiment of the present techniques. In these views 600, 620, and 640,the autonomous tool 602 may provide a mechanism for selective placementof each perforating gun component 604, 606 and 608 for each individualzone to enhance well productivity.

FIG. 6A is a side view 600 of a portion of a wellbore and the subsurfaceformation near the wellbore for initial deployment of the autonomoustool. In this view 600, the autonomous tool 602 may include perforatinggun components 604, 606 and 608, which are coupled together as a singleautonomous tool for the deployment into the wellbore. The wellbore mayinclude a casing string 610 surrounded by a cement sheath 613. Thewellbore is disposed within a subsurface formation including three zonesof interest, such as first zone 614, second zone 616 and third zone 618.Further, to assist the identification of the location within thewellbore, various tags, such as tag 612, may be disposed within thewellbore.

FIG. 6B is a side view 620 of a portion of a wellbore and the subsurfaceformation near the wellbore for a subsequent stage in the tubularoperations. In this stage, the first perforating gun component 604separates from the remaining perforating gun component 606 and 608 todeploy within the first zone of interest 614. In this view 620, theperforating gun components 606 and 608 are coupled together as theremaining actuatable tool components traveling to the lower locations,such as zones of interest 616 and 618.

FIG. 6C is a side view 640 of a portion of a wellbore and the subsurfaceformation near the wellbore for a final stage in the tubular operations.In this stage, the perforating gun components have detonated to form theperforations 642, 644, and 646 for the respective zones. In particular,the first perforating gun component 604 forms the perforations 642 inthe first zone of interest 614, the second perforating gun component 606forms the perforations 644 in the second zone of interest 616, while thethird perforating gun component 608 forms the perforations 646 in thethird zone of interest 618.

As additional enhancements, the autonomous tool may include otheractuatable tool components. For example, the additional actuatable toolcomponents may provide diversion between zones of interest 614, 616 and618 to ensure each zone is treated per design and previously treatedzones of interest 614, 616 and 618 are not inadvertently damaged.Further, the autonomous tool may provide a mechanism for stimulationtreatments to be pumped at high flow rates to facilitate efficient andeffective stimulation. As such, the autonomous tool may enhance tubularoperations, such as multi-zone stimulation techniques and the associatedhydrocarbon recovery from subsurface formations that contain multiplestacked subsurface intervals. With the use of autonomous toolscontaining dissolvable materials, surface equipment utilization in agiven time period may be enhanced (e.g., high pressure pumpingequipment). The enhancement is a result of the lessening or removal ofthe need or requirement to remove debris along with enhancedcapabilities to run more components and perform more tubular operationson a single run with materials that dissolve within the tubularconditions.

While it will be apparent that the inventions herein described are wellcalculated to achieve the benefits and advantages set forth above, itwill be appreciated that the inventions are susceptible to modification,variation and change without departing from the spirit thereof.

What is claimed is:
 1. An autonomous tool for performing a tubularoperation, comprising: an actuatable tool component configured toperform a tubular operation; a location component configured todetermine a location of the autonomous tool within a tubular member; andan on-board controller configured to send an actuation signal to theactuatable tool component when a predetermined location has been reachedwithin the tubular member; wherein: the actuatable tool component, thelocation component, and the on-board controller are arranged to bedeployed together in the tubular member as a single autonomous tool; theactuatable tool component is configured to autonomously perform thetubular operation in response to the actuation signal; and at least aportion of the actuatable tool component, the location component, andthe on-board controller are fabricated from a dissolvable materialconfigured to dissolve when subjected to tubular conditions.
 2. Theautonomous tool of claim 1, wherein the location component is furtherconfigured to determine the location of the autonomous tool based onidentifying casing collars within the tubular member, wherein thelocation component is configured to compare a depth signature formed bythe spacing of the casing collars along the tubular member, with apredetermined signature generated prior to deployment of the autonomoustool into the tubular member.
 3. The autonomous tool according to claim1, wherein the location component is further configured to determine thelocation of the autonomous tool based on identifying radio frequencyidentification tags within the tubular member, wherein the locationcomponent is configured to compare a signature formed by the identifiedradio frequency identification tags within the tubular member, with apredetermined signature generated prior to deployment of the autonomoustool into the tubular member.
 4. The autonomous tool according to claim1, wherein the location component is further configured to determine thelocation of the autonomous tool based on pressure measurements withinthe tubular member, wherein the location component is configured tocompare a signature formed by the measured pressures within the tubularmember, with a predetermined signature generated prior to deployment ofthe autonomous tool into the tubular member.
 5. The autonomous toolaccording to claim 1, wherein the autonomous tool further comprises asecond location component to determine a second location of theautonomous tool within the tubular member, wherein the second locationcomponent utilizes a different location detection technology from thelocation component.
 6. The autonomous tool according to claim 1, whereinthe autonomous tool self-destructs in response to one of the actuationof the actuatable tool component, the determination of elapsing of aselected period of time by the on-board controller, and any combinationthereof.
 7. The autonomous tool according to claim 1, wherein theactuatable tool component is a perforating gun component that issubstantially fabricated from a dissolvable material.
 8. The autonomoustool according to claim 1, wherein the actuatable tool component is aball sealer component that is substantially fabricated from adissolvable material.
 9. The autonomous tool according to claim 1,wherein the remaining portion of the autonomous tool is fabricated froma friable material or a millable material.
 10. The autonomous toolaccording to claim 1, wherein the autonomous tool further comprises asecond actuatable tool component configured to perform a second tubularoperation, wherein: the on-board controller is further configured tosend a second actuation signal to the second actuatable tool componentwhen the predetermined location has been reached within the tubularmember; the actuatable tool component, the second actuatable toolcomponent, the location component, and the on-board controller arearranged to be deployed together in the tubular member as a singleautonomous tool; and the second actuatable tool component is configuredto autonomously perform the second tubular operation in response to thesecond actuation signal.
 11. The autonomous tool of claim 10, whereinthe on-board controller manages the sequence of tubular operations. 12.The autonomous tool according to claim 10, wherein the actuatable toolcomponent is a first perforating gun component and the second actuatabletool component is a second perforating gun component.
 13. The autonomoustool according to claim 10, wherein the actuatable tool component is afirst perforating gun component and the second actuatable tool componentis a bridge plug component.
 14. The autonomous tool according to claim10, wherein the actuatable tool component is a first perforating guncomponent and the second actuatable tool component is a shockwavecomponent.
 15. A method for performing one or more tubular operations,comprising: deploying an autonomous tool into a tubular member, whereinat least a portion of the autonomous tool is fabricated from adissolvable material and the autonomous tool is configured toautonomously perform the one or more tubular operations; autonomouslyperforming the one or more tubular operations with the autonomous tool;dissolving the at least a portion of the autonomous tool that isfabricated from the dissolvable material; and managing hydrocarbons fromthe tubular member.
 16. The method according to claim 15, wherein theautonomous tool comprises: an actuatable tool component configured toperform a first tubular operation of the one or more tubular operations;a location component configured to determine a location of theautonomous tool within the tubular member; and an on-board controllerconfigured to send an actuation signal to the actuatable tool componentwhen a predetermined location has been reached within the tubularmember; wherein: the actuatable tool component, the location component,and the on-board controller are arranged to be deployed together in thetubular member as a single autonomous tool; and the actuatable toolcomponent is configured to autonomously perform the tubular operation inresponse to the actuation signal.
 17. The method according to claim 15,further comprising determining the location of the autonomous tool basedon identified casing collars disposed along the tubular member.
 18. Themethod according to claim 15, further comprising determining thelocation of the autonomous tool based on identified radio frequencyidentification tags within the tubular member.
 19. The method accordingto claim 15, further comprising determining the location of theautonomous tool based on pressure measurements within the tubularmember.
 20. The method according to claim 17, wherein the determiningthe location of the autonomous tool further comprises determining thelocation of the autonomous tool based on two or more location detectiontechnologies.
 21. The method according to claim 16, further comprisingmanaging a sequence of the one or more tubular operations with theon-board controller.
 22. The method according to claim 16, wherein theautonomous tool further comprises a second actuatable tool component andfurther comprising performing a second tubular operation with the secondactuatable tool component.
 23. The method according to claim 15, whereinthe autonomously performing the one or more tubular operations with theautonomous tool further comprises performing a first perforatingoperation with a first perforating gun component of the autonomous tool;and performing a second perforating operation with a second perforatinggun component of the autonomous tool.
 24. The method according to claim15, wherein the autonomously performing the one or more tubularoperations with the autonomous tool further comprises performing aperforating operation with a perforating gun component of the autonomoustool; and performing a bridging operation with a bridge plug componentof the autonomous tool.
 25. The method according to claim 15, furthercomprising self-destructing the autonomous tool in response to one ofthe actuation of the actuatable tool component, the determination ofelapsing of a selected period of time by the on-board controller, andany combination thereof.